Technical Field
The present invention relates to processes and techniques for crude oil recovery. More specifically, the present invention relates to processes for enhancing in situ generation of carbon dioxide in an oil reservoir that in turn results in increased oil recovery.
Description of the Related Art
The “background” description provided herein is for the purpose of generally presenting the context of the disclosure. Work of the presently named inventors, to the extent it is described in this background section, as well as aspects of the description which may not otherwise qualify as prior art at the time of filing, are neither expressly or impliedly admitted as prior art against the present invention.
Crude oil development and production in global oil reservoirs can include up to three distinct phases: primary, secondary and tertiary (or enhanced) recovery. During primary recovery, reservoir drive comes from a number of natural mechanisms. These include: natural water displacing oil downward into the well, expansion of the natural gas at the top of the reservoir, expansion of gas initially dissolved in the crude oil, and gravity drainage resulting from the movement of oil within the reservoir from the upper to the lower parts where production wells are located. Only about 10% (e.g. 5-15%) of a reservoir's original oil in place is typically produced by the natural mechanisms of primary recovery. Secondary techniques extend a field's productive life after the natural reservoir drive diminishes, generally by injecting external energy in the form of water (e.g. water injection or waterflooding) or gas to increase the reservoir pressure, so that the oil can be artificially displaced and driven to a production wellbore, resulting in the recovery of 20-40% of the original oil in place.
As global energy demand continues to surge and the amount of easy-to-produce oil (by primary and secondary recoveries) diminishes rapidly, oil producers are investing and searching for methods to increase oil recovery, including the recovery of residual oil from a growing number of mature oil fields that have already been subjected to primary and secondary recoveries. The residual oil is usually heavy: having high viscosity and therefore resulting in low oil mobility.
Techniques in enhanced oil recovery (EOR) offer prospects for ultimately producing 30-60%, or more, of the reservoir's original oil in place. EOR processes attempt increase the recovery factor by focusing on the rock/oil/injectant system (e.g. wettability of reservoir rocks) as well as the interplay of capillary and viscous forces (i.e. to reduce the viscosity and thereby increase the mobility of the oil especially the residual oil). Three major categories of EOR have been found to be commercially viable to varying degrees: thermal recovery, gas injection (e.g. natural gas, N2 or CO2) and chemical injection (e.g. polymer flooding and microbial injection).
The EOR technique that has attracted the most new market interest is CO2-EOR. In the U.S., CO2 injection has been implemented through the Permian Basin of West Texas and eastern New Mexico, and is now also being pursued at varying extents in other states such as Kansas, Mississippi, Wyoming, Oklahoma, Colorado, Utah, Montana, Alaska and Pennsylvania.
CO2 is effective in recovering oil from a reservoir because it promotes swelling of the oil, reduces the viscosity and vaporizes portions of crude oil as it is being transported through the porous rock. However, as CO2 is highly mobile, this technique encounters problems of viscous fingering, reservoir heterogeneity and gravity overriding or segregation, as the ability to control the mobility of CO2 is limited.
Attempts to reduce the mobility of CO2 include in situ generation of CO2 in oil reservoirs and injection of CO2 in a supercritical fluid state or as carbonated water. These strategies can also be accompanied by the injection of chemicals such as viscosifiers, surfactants and nanosilica particles for foam formation.
US 2014/0338903A1 describes the use of HEDTA chelating agents at low pH values to generate CO2 in situ in carbonate cores. This method is good for in situ CO2 generation at near wellbore regions but not for deep placement and maximum contact with the reservoir as the HEDTA or any low pH chemical, having no retarding mechanisms for their reaction, will be consumed at the reservoir.
Gumersky et al. uses a gas-forming solution containing water and a mixture of low concentrated acid and low concentrated surfactant and polymer. The solution forms a stable foam and while penetrating through barrier-blocking high permeable layers and into low permeable layers, the gas-forming solution shows visco-elastic properties and displaces oil from them. This method improved water flooding efficiency by 20-30% and the ultimate oil recovery improved marginally by 3-5% compared to traditional water flooding [Gumersky, K., Dzhafarov, I. S., Shakhverdiev, A. K. and Mamedov, Yu. G. 2000. In-Situ Generation of Carbon Dioxide: New Way to Increase Oil Recovery. Paper SPE 65170-MS presented at SPE European Petroleum Conference, Paris, France, 24-25 Oct. 2000—incorporated herein by reference in its entirety].
Shiau et al. heat ammonium carbamate above 85° C. to produce CO2 which reduced oil viscosity and this ammonium carbamate when used with surfactant polymer chemical flood and an enhanced oil recovery of 9.7% was recorded [Shiau, B. J. B., Hsu, T.-P., Roberts, B. L., & Harwell, J. H. 2010. Improved Chemical Flood Efficiency by In Situ CO2 Generation. Paper SPE 129893-MS presented at the SPE Improved Oil Recovery Symposium, 24-28 April, Tulsa, Okla., USA—incorporated herein by reference in its entirety].
Xiaofei et al. generate in situ CO2 using active acid, polymer, and surfactant to solve the problem of reservoir heterogeneity and high water to oil viscosity ratio which results in monolayer and monodirectional flow. CO2 flooding reduced injection pressure and effectively plugged channeling between injection-production wells. Their system increased the swept volume, increased oil, and decreased water cut [Xiaofei J., Kuiqian M., Yingxian L., Bin L., Jing, Z., and Yanlai L. 2013. Enhanced Heavy Oil Recovery by In-Situ Carbon Dioxide Generation and Application in China Offshore Oilfield. Paper SPE 165215 presented at The SPE Enhanced Oil Recovery Conference held in Kuala Lumpur, Malaysia, 2-4 Jul. 2013—incorporated herein by reference in its entirety].
U.S. Pat. No. 8,616,294 describes an apparatus for generating carbon dioxide gas in situ at an oil site for use in enhanced oil recovery (EOR). The apparatus includes a steam generator adapted to boil and superheat water to generate a source of superheated steam, as well as a source of essentially pure oxygen. The apparatus also includes a steam reformer adapted to allow the reaction of a carbonaceous material with the superheated steam and the pure oxygen, in an absence of air, to generate a driver gas comprising primarily carbon dioxide gas and hydrogen gas.
US 2014/0231080A1 describes use of acid and sodium bicarbonate to generate CO2 in the wellbore itself but not the reservoir. The CO2 that is generated in situ will increase the pressure inside the wellbore to lift the oil from the bore.
In view of the above, there remains an apparent need for in situ CO2 generation systems and methods that can reach deep into oil reservoir and sustain the actual reservoir conditions. The present disclosure aims to provide a method having a different approach towards in situ generation of CO2 in carbonate and sandstone reservoirs.